Presentation on theme: "Part 3.1 Production Practices. Objectives After reading the chapter and reviewing the materials presented the students will be able to: Understand wellhead."— Presentation transcript:
Part 3.1 Production Practices
Objectives After reading the chapter and reviewing the materials presented the students will be able to: Understand wellhead equipment that controls fluid flow Examine artificial methods of lifting fluids Discuss methods of handling well fluids on the surface Analyze well servicing and work over operations
Introduction Production is a combination of preparing the borehole for production, bringing fluids to the surface, and separating into oil, gas, and water streams that are measured for quality and quantity. Servicing such as replacing worn or malfunctioning equipment is standard during the well’s producing life. Later, more extensive repairs, known as workovers, might be necessary, to maintain the flow of oil and gas.
Well Completion Many oil and gas wells require four strings of large pipe, each one reaching the surface. The four strings include: conductor pipe, surface casing, intermediate casing, and production casing. Production casing is often called the oil string and is the final casing for most wells. The other casing strings are installed during the drilling phase to stabilize and protect shallower portions of the well. Another type of production casing often used in deeper wells (over 10,000 feet) is called the liner. A liner hangs from the end of the larger casing above it by means of a line hanger. A liner uses less pipe and requires shorter installation time, therefore it is less expensive than production casing.
Completion Types Onshore, it is common to use a completion rig that is smaller and less expensive than the larger drilling rig used to drill the hole and install the casing. Offshore it is common to use the drilling rig to install the completion to avoid the cost of bringing in different rigs. Open Hole Completion: An open hole completion has no production casing or liner. This type of completion is limited to reservoirs in which the reservoir rock will not collapse or come apart and fill up the hole when fluid flows. Cased and Perforated Completion: A cased and perforated completion requires the production casing to be run completely past the reservoir and cemented in place. The connection between the inside of the casing and the producing reservoir is made by perforating holes through the casing and cement. Tubingless Completions: The advantage of a tubingless completion is primarily cost. Many wells begin life as a tubingless completion and are later converted to use tubing.
Tubing & Packers After cementing the production casing and creating an open hole or perforations, the completion crew runs a final string of pipe called tubing. Well fluids flow from the reservoir to the surface through this tubing. Unlike casing, tubing is not cemented but hangs from the wellhead at the surface. Tubing can be easily removed if it becomes damaged or corroded. Tubing can be sealed at the bottom using a packer. A packer consists of metal housing with external slips, rubber elements, and an internal flow tube. It provides a secure seal between everything above and below where it is set. Because the packer seals off the space between the tubing and the casing, formation fluids must flow up the tubing to reach the surface.
Multiple Completions The operator uses a multiple completion when one wellbore passes through two or more zones containing oil and gas that are to be produced simultaneously. Usually a separate tubing string with packers is run for each producing zone. Multiple completions allow production of separate reservoirs in one wellbore, is more expensive and complicated to install, often less expensive to drill than multiple wells, more difficult to employ pumps, and repairs can take longer.
Subsurface Safety Valve A subsurface safety valve (SSSV) is required in every tubing string on all offshore wells. The valve must be set several hundred feet below the ocean floor (mud line) to prevent pollution in case of a catastrophe, such as loss of the wellhead in a storm. The SSSV is not a requirement for onshore completions.
Gravel Pack Completions Some reservoirs produce not only oil and gas, but also sand. The most common method of controlling sand is called gravel pack. In a gravel pack, well sorted sand is pumped through the perforations. Some of the gravel is left inside the wellbore and held in place by a wire wrapped screen. The screen prevents the passage of gravel in the wellbore.
The Wellhead The wellhead includes all equipment on the surface that supports various pipe strings, seals off the well, and controls the paths and flow rates of reservoir fluids. A casinghead is a heavy steel fitting at the surface. Metal and rubber seals in the casinghead prevent fluids from moving within the wellhead or escaping to the atmosphere. The first casinghead is often called the brandenhead. It is welded or screwed on top of the surface casing. The second casinghead is called the intermediate spool. It is placed over the intermediate casing. Production casing is landed either in the brandenhead or in the intermediate spool and sealed. The tubing head is placed on top. It supports the tubing string and seals off pressure between the casing and inside of the tubing. It has outlets to gauge pressure or connect valves and fittings to control fluid flow.
Christmas Tree Placed on top of the tubing head is a series of valves called the upper tree assembly, also called the Christmas tree. The valves on the Christmas tree control the flow from the tubing. The flow rate from the well is controlled by a slight restriction in the flow line, called the choke. For offshore wells in deepwater where a platform is not possible, the wellhead must be placed on the seafloor or the mud line. Subsea well heads are called wet trees because they are under water. Wellheads placed on an offshore platform above sea level are called dry trees.
Initiating Flow The drilling fluid is replaced by some form of completion fluid during completion. If the completion fluid in the well exerts a higher pressure than the reservoir, no reservoir fluid can enter the well. Some of the heavy completion fluid must be removed or replaced with a less dense fluid so the reservoir pressure can allow fluids to flow into the well. To remove heavy completion fluid in a well, the following methods are used: swabbing, jetting, and replacing fluids with less dense fluids. Some wells will not generate enough reservoir pressure to flow fluids all the way to the surface. These wells require extra equipment to artificially lift the fluids to the surface.
Simulation For reservoirs with small values of permeability, it is often possible to improve permeability by applying one or more simulation techniques. Three main ways to simulate permeability are explosive fracturing, acidizing, and hydraulic fracturing. Explosives: Crews explode nitroglycerine inside wells to improve productivity. The explosion pulverizes rock around the well improving permeability of flow. Hydraulic Fracturing: The fractures are created by high pressure injection of fluids. The hydraulic pressure fractures the rock. Proppants hold the fracture open. Sand, ceramic beads or bauxite are used. Fracturing fluid can be created using either oil or water. Acidizing: In acid stimulation, an acid reacts chemically with the rock to dissolve it. Additives are used to prevent the acid from attacking the steel tubing or casing in the well. Antisludge agents prevent acid from reacting with crude to form a sludge that reduces permeability.
Artificial Lift The most common method of pumping oil from a formation to the surface in land based wells is beam pumping. The pumping unit sits on the surface. The unit converts rotary motion of the prime mover to reciprocating or up and down motion at the horsehead. During the upstroke, reservoir fluids enter the barrel of the pump that is being emptied by the upward motion of the plunger.
Electric Submersible Pumps (ESPs) The pump and motor are placed in the well at the end of the tubing. The motor is powered by electricity sent down an armored cable from the surface. ESPs are expensive to buy, and their electric power cost can be very high. Electric Submersible Pumps (ESPs) are used in high volume wells where volumes pumped are larger than can be handled by other artificial lift devices.
Subsurface Hydraulic Pumps Subsurface hydraulic pumps are placed at the bottom of the well in the tubing and function by pumping power fluid (oil or water) down the well through tubing to the pump. The power fluid mixes with the produced fluid and is pumped back to the surface. Next the power fluid is separated from the produced fluid in the surface facility and reused. Subsurface pumps are expensive and subject to erosion by produced fluid.
Gas Lift Gas lift mixes natural gas from another source with the reservoir fluids in the well. The added gas reduces the mixture density to a point where the remaining reservoir pressure causes the fluid to flow to the surface. The extra gas needed to reduce fluid density is injected down the tubing. Enough reservoir pressure must be present to cause the lower density fluid mixture to flow to the surface.
Reservoir Drive Mechanisms The flow of fluid always occurs from an area of high pressure to an area of low pressure. The bottom of the well is a lower pressure area compared to the pressure in the reservoir. If sufficient reservoir pressure remains at the bottom of the well, the fluid flows to the surface. The first period in the producing life of a reservoir is called primary recovery or primary production. Reservoir drive mechanisms include: depletion drive, water drive, gravity drainage, and a combination of these.
Depletion Drive As the fluids flow out of the reservoir, the reservoir pressure begins to decline. When the pressure decreases, the compressed fluids begin to expand. As long as the reservoir pressure is slightly larger than the pressure in the well gas will continue to flow. The recovery of gas by depletion drive is very high, as much as 80% of the original gas in place.
Water Drive In this case, the oil and gas reservoir exists on top of a large water section. The water bearing part of the reservoir is called aquifer. The water can provide enough expansion to keep the reservoir pressure high. With a strong water drive, oil recovery can reach 50 to 60 % of the original oil in place.
Gravity Drainage Gravity drainage occurs in the downhill part of a reservoir. The force of gravity causes oil to flow downhill into the well. Oil recovery with gravity drainage can be as high as 50% of the original oil but recovery time can be long and production rates low. Gravity drainage is not as helpful in gas reservoirs.
Well Testing Well testing can be done for the following reasons: To monitor the production capability of a well. To determine the changes in production capability of a well. To determine the reservoir drive mechanism. To estimate how much oil and gas might be recovered over time.
Potential or Production Tests Production rates and flow pressures are carefully measured over the period of flow. Lease operators collect produced fluid samples to analyze. A bottom hole production test uses a gauge to measure pressure at or near the bottom of the well. Pressure data recorded over time can be used to detect reservoir damage that might occur near the well.
Improved Recovery Techniques Depending on the reservoir drive mechanism, a substantial amount of oil will be left in the reservoir at the end of primary production. The major methods of improved oil recovery are: water flooding, gas injection, chemical flooding, and thermal recovery. Water flooding: Carefully selected wells undergo an injection of water to refill the reservoir and restore reservoir pressure. Immiscible gas injection: An immiscible gas is one that will not mix with oil. The gas expands to provide additional reservoir pressure to keep the oil flowing to the well. Miscible gas injection: When the gas mixes with oil, the oil’s viscosity is reduced, allowing the oil to flow more freely to the well. Injection gases include LPGs (liquefied petroleum gases) such as propane, methane, and carbon dioxide used alone or followed by water. Chemical flooding: is a general term used for injection processes that use special chemicals in water to push oil out of the formation. Thermal recovery: Recovery techniques that use heat are called thermal recovery. Steam injection involves forcing steam down injection wells into the reservoir to heat up the oil and reduce its viscosity. The hot water acts like a waterflood and moves the thinned oil to production wells where oil and water are produced.
Surface Handling of Well Fluids The well steam is passed through a series of separating and treating devices to separate the oil, gas, and water. The oil is temporarily stored and tested for quality. It is then sold and transported to the refinery. The gas is tested for hydrocarbon content and impurities. It is sometimes compressed to a high pressure. The gas is then sold through a pipeline. The water is reused or sent to a disposal well.
Separating Liquids from Gases The gas separates from the liquid inside the horizontal or vertical vessel. A float monitors the liquid level inside the separator and opens a valve to automatically let some liquid flow out of the vessel when the correct level is reached. A device on the gas outlet, called a back pressure regulator holds a certain amount of pressure on the vessel. The gas can be boosted to the correct pressure by a gas compressor so it can enter the pipeline.
Removing Free Water The liquids dumped from the two phase separator are oil, water, and am emulsion (oil water mix). The water not emulsified with oil is known as free water. A free water knockout (FWKO)is a vertical or horizontal vessel that provides space for the free water to settle out of the well stream. There are three phases separated in this vessel: free water, emulsion or oil, and gas that comes out of the oil. Therefore this type of separator is called a three phase separator. The advantage of removing the free water at this point is to reduce the volume of liquid that must be treated in the final separator.
Treating Emulsified Oils If an emulsion is present, the final separation occurs in an emulsion treater. Emulsifiers that help form petroleum emulsions are asphalt, resinous substances, or oil soluble organic acids. Treatments use chemicals, heat, or electricity along with gravity. Chemical Treatment: Chemicals called demulsifiers are added to the emulsion to make the droplets of water merge, or coalesce. When water droplets merge, they become bigger, and bigger droplets settle faster than smaller ones. Heat Treatment: When an emulsion is heated, the water droplets merge and separate from the oil. Treatment with Electricity: When an electric current disturbs the emulsion, adjacent water droplets coalesce until large drops form and settle out by gravity.
Types of Emulsion Treaters Heater-Treater: A heater-treater is a three phase separator with an internal fire tube. Emulsions are heated around F. The oil that separates from the emulsion floats to the top of the emulsion, the water that separates sinks to the bottom, and any gas evolving from the oil exits at the top. Electrostatic Treater: This treater features a high voltage electric grid. The advantage of an electrostatic treater is that no fire is present. The disadvantage is that electricity must be available and the electric grid inside the vessel is more prone to breakdown than the gas fired treater. Controlling Paraffin: Paraffin is a white hydrocarbon wax sometimes found in petroleum. Paraffin can severely reduce the efficiency of oil and gas separators by building up in the vessel or blocking fluid passages. Steaming and using solvents are effective controls, but the most common method is to keep the oil at a temperature warmer than the cloud point (paraffin formation temperature).
Preventing Hydrate Formation The operator installs a regulator (choke) to reduce pressure or a compressor to raise pressure as needed. Most natural gas contains substantial amount of water vapor. If the water vapor cools below a certain temperature, hydrates can form. It often resembles dirty snow. An indirect heater is the most common equipment used to prevent natural gas hydrates from forming. The choke is often placed at the entrance to the heater so the gas can be rapidly heated above hydrate temperature after being cooled by expansion across the choke.
Dehydrating Many pipeline companies will not buy gas containing more than 7 pounds of water per million cubic feet of gas. The water in gas must be removed by a process called dehydration. Two dehydration methods are used – absorption and adsorption. In absorption, the gas is bubbled through a contact tower filled with a liquid desiccant called glycol that absorbs the water vapor. The dehydrated gas exits at the top of the contact tower. The saturated glycol can be regenerated in a boiler, because water boils at a temperature lower than glycol. In adsorption, the water vapor laden gas is passed over a solid desiccant. The desiccant can be reused after it is dried by heating and vaporizing the water.
Removing Contaminants Natural gas often contains carbon dioxide and hydrogen sulfide. These gases are called acid gases because they form acids or acidic solutions in the presence of water. Gases with high concentrations of sulfur are also called sour gases. Removing these contaminants from natural gas is often called sweetening the gas. Two types of absorption processes are applied using chemical and physical means to remove acid gases from the natural gas. In chemical absorption, the liquid absorbent (amine) reacts chemically with the acid gas but not with the natural gas. In physical absorption the acid gases physically dissolve in the liquid absorbent and the natural gas does not. Commercial absorbents include Selexol, sulfinol, Rectisol, and Fluor Solvent processes. In adsorption the acid gas flows over solid adsorbent, as in dehydrating.
Removing Natural Gas Liquids Natural gas is a mixture of methane, ethane, propane, and some heavier hydrocarbons such as butane, pentanes, nonanes and decanes. In field separators, some of the heavier hydrocarbons liquefy and are removed and sold. The liquefied hydrocarbons known as natural gas liquids (NGLs) are more valuable as a liquid fuel or refinery feedstock. The usual equipment for processing gas from a gas well is a low temperature separation unit. This equipment partially dehydrates the gas stream and removes the NGLs. The NGL is stored in a low pressure tank and the water is disposed off.
Storing Crude Oil Oil, natural gas liquids, and water that have been separated are temporarily stored in a group of stock tanks or a tank battery. Onshore, the total storage capacity of a tank battery is usually three to seven days of production. Offshore, after treating, the oil and gas are generally sent to the shore in a pipeline. To measure the amount of oil in a tank, a technician called a gauger lowers a steel tape that has been carefully grounded with a weight on the end into the tank until it touches the bottom. The highest point at which oil wets the tape shows the level or height of the oil in the tank. The gauger records the level and calculates volume using tank tables.
Tank Construction Most tanks are constructed of either bolted or welded steel. They have a bottom drain outlet for draining off sediment and water (S&W). Sometimes a worker must enter an empty tank to clean out paraffin and sediment that cannot be removed through the drain outlet. Breathing apparatus may be required and proper safety procedures must be followed. Oil enters the tank at the top at an inlet opening. The pipeline outlet is approximately one foot above the bottom of the tank. The space below this outlet provides room for the collection of S&W. Water is frequently stored in fiberglass tanks. The lease operator owns the gas and oil as it comes out of the well. The operator then sells it, and the pipeline company transports it to the buyer. The operator, pipeline company, and buyer measure and test the oil and gas at different times.
Oil Sampling Because the procedure for taking samples vary, both the operator and pipeline must agree on how they are done. A gauger frequently samples oil using thief sampling using a round tube about 15 inches long called a thief lowered in the tank. Average sample consists of proportionate parts from all sections of the tank. Running sample is a bottle sample taken while the sample bottle is moving. Spot sample is obtained at a specific location in the tank using a thief or a bottle. This is the most common method for lease tanks.
Measuring and Testing Oil and Gas Crude oil is bought, sold, and regulated by volume, S&W content, sulfur content, and oil gravity or density. The operator usually measures the volumes of oil, gas, and saltwater produced by each lease at least once every 24 hours. Gaugers run the tests and measurements. The information they get is written on the pipeline run ticket.
Gravity, S&W, and Sulfur Content Measurement The maximum S&W content in most states is 1%. A centrifuge test, also called a shakeout test determines the S&W content of the samples. The test uses a glass centrifuge tube that is graduated so the percentage of S&W can be read directly. An instrument called a hydrometer measures the API gravity of the oil. The hydrometer floats at a certain level in the crude : the higher it floats, the lighter the oil. The markings on the hydrometer show the observed gravity. The sulfur content must be determined in the lab using an oil sample.
LACT Units The development of lease automatic custody transfer (LACT) units has improved efficiency and reduced the time necessary to measure, sample, test, and transfer oil. Automatic equipment can perform the following tasks: measure and record the volume of oil, detect the presence of water, determine and record the temperature of the oil, and in case of malfunction shut the well and relay an alarm. LACT units are necessary in installations that process a large volume of oil every day.
Gas Sampling Sampling is the way the operator determines the composition, heating value, specific gravity, and potential of the gas being produced from a well. The most common places for sampling are the separator, and at the sales point, with samples at the sales point being taken for custody transfer purposes. Although manual sampling methods are more common, automatic sampling devices connected to the pipeline are also used. In most cases field samples are sent to the lab for testing.
Gas Testing The most common method is fractional analysis. Fractional analysis is a lab test that determines the exact composition of the gas. Heating value is the amount of heat in Btu/scf (British thermal unit per standard cubic foot) that the gas will produce when burned. The analysis determines the gas composition and the temperature and pressure of the sample that can be used to compute how much gas can be converted to natural gas liquids. The analysis also determines the quantity of impurities in the gas such as oxygen, nitrogen, carbon dioxide, and hydrogen sulfide. Because hydrogen sulfide reacts with metal and is reduced by contact with the sample container it must be analyzed at the well site.
Gas Metering Gas metering is the process of measuring the volume of natural gas flowing past a particular point. Gas is compressible, so the volume flowing past any point will change if the temperature, pressure, or gas composition changes. Standard temperature and pressure are normally 60 0 F and pounds per square inch (Texas and Oklahoma are and Louisiana is ). Gas must be metered whenever there is a change of custody or ownership. The most common method of measuring the gas is an orifice meter. Electronic flow computers can gather data from these meters, calculate flow rate, and transmit information to the office.
Well Service and Workover Well service is maintenance work that usually involves repairs to equipment installed during completion of the well. Well workover includes procedures viewed as more complicated and expensive conducted on a well to restore or increase production.
Rigs Service and workover rigs, like drilling rigs, are machines that hoist pipe and tools into and out of a well. The rig type depends in part on the weight and size of the equipment it must carry. Truck mounted rigs are small rigs that usually rest on custom built trucks. Trailer mounted rigs are large rigs that sit on trailers pulled by tractors. Carrier rigs are rigs that have a built in cab for an operator so the rig can be driven from location to location.
Wireline Units Wireline operations are procedures performed with tools suspended on wireline. Wireline, in essence, is a strong, thin length of wire mounted on a powered reel at the surface of a well. The simplest and weakest type of wireline is a single stainless steel wire called a slick line. Slick lines can hoist lightweight tools into a well. A stronger wireline is a braided steel line. It is used to hoist heavier tools in a well. Among the more common jobs performed with wireline are: measuring depth, temperature, and pressure; logging; perforating; controlling sand and paraffin; fishing and retrieving junk; and manipulating subsurface well pressure and flow controls. Wireline along with the equipment required to perform various wireline operations are usually housed in a truck or small portable house on a skid and are called wireline units. Electric wireline units also must have the controls and data acquisition units for the electronic equipment.
Coiled Tubing Units A coiled tubing unit is a reel of flexible continuous steel tubing coiled onto a drum. The coiled tubing is transported to a well on a truck, barge, or service boat. The unit has a injector head that pushes or pulls the tubing into or out of the well. A set of blowout preventers also comes with the unit to control well pressure. Up to 25,000 feet of diameters up to 1.25 inches can be carried on one reel. Depending on the size and type coiled tubing an be used with pressures up to 15,000 psi. On many jobs, using a coiled tubing unit instead of a workover rig and jointed pipe is faster and less expensive.
Snubbing Units Snubbing units are rigs that allow jointed pipe to be run into or pulled out of a well while the well is under pressure. Operations using jointed pipe are preferable to coiled tubing if the pressure is higher than the pressure rating of the coiled tubing, or if the job is extremely hazardous. The snubbing unit has a top and bottom set of blowout preventers. Hydraulic units operate with a self contained hydraulic system and uses single or multiple hydraulic cylinders to move the pipe in or out of the well. Rig assisted units use the rig drawworks in a block and pulley arrangement to move the pipe.
Auxiliary Equipment Auxiliary equipment that might be required by a well servicing and workover rig includes: crew quarters, electric generators and lights, fuel tanks, blowout preventers, makeup and breakout tongs, racks for storing pipes, top drive or a rotary to rotate pipe, pumps, mud mixing equipment, and mud or fluid completion storage tanks. The circulating fluid used in servicing a workover is called workover fluid. More often the workover fluids are brine. Extremely dense workover fluids can be made from calcium or zinc bromide, or potassium or cesium formate.
Well Servicing & Repair Well equipment frequently becomes worn from corrosion, abrasion or erosion, or metal fatigue. Produced fluids can cause corrosion and resulting pitting in the well tubing. Proper care of beam pumping equipment includes correct lubrication and counterbalance adjustment. Sucker rods, couplings, and downhole pumps can fail for many reasons including corrosion, hydrogen sulfide, or carbon dioxide. Over time tubing can become worn by abrasion with sucker rods or pitted due to corrosive attack. The tubing must be pulled from the well, inspected, defective sections replaced, and the tubing string run back in the well. An inspection can locate worn tubing before it fails in the well. An electronic test measures wall thickness of a tube. Paraffin deposits can be cleaned with a scraper run in on a wireline or by pumping hot oil or hot water down the casing to melt the paraffin in the tubing.
Workover Operations Workover operations are intended to improve production from the well. Workovers include cleaning sand out of the well, adding a means of preventing sand from entering the well, plugging an old zone in the well, and recompleting in a new zone, repairing casing, and drilling deeper. Sand Cleanout: The sand c an sometimes be cleaned out of the well with a wireline bailer lowered to the bottom of the well. If there is more sand than can be economically removed with a bailer, it is sometimes possible to wash or circulate the sand out of the well using fluid. If the sand is packed hard in the well, a small bit with a downhole motor can be used on coiled tubing to drill the sand out. Sand Control: For wells that continue to produce sand, gravel packing can be done to prevent sand flow into the wellbore. Another methods is to glue the sand grains together in the reservoir with a plastic or resin (chemical consolidation). Another method is to create a small fracture at the well and pack it full of high quality resin coated sand (frac packing).
Workover Operations Plug Back Cementing: It is a process that places a cement plug at one or more points in a well to shut off flow from a depleted or non productive zone of oil or gas. Sidetracking is the process of drilling a new hole that is deviated to change the location of the bottom of the well. Casing & Production Liner Repair: Squeeze cementing is one way of repairing holes in casing. Other methods are patching it with a liner patch. Expandable tubulars are also used as a patch or liner to help preserve the largest diameter of casing available. Squeeze Cementing: Unlike plug back cementing, the cement is forced to go outside the casing and into the formation beyod the casing. In this way the cement forms both an external and internal seal.
Summary Many oil and gas wells require four strings of large pipe, each one reaching the surface. The four strings include: conductor pipe, surface casing, intermediate casing, and production casing. A cased and perforated completion requires the production casing to be run completely past the reservoir and cemented in place. The connection between the inside of the casing and the producing reservoir is made by perforating holes through the casing and cement. After cementing the production casing and creating an open hole or perforations, the completion crew runs a final string of pipe called tubing. Well fluids flow from the reservoir to the surface through this tubing. The operator uses a multiple completion when one wellbore passes through two or more zones containing oil and gas that are to be produced simultaneously. A subsurface safety valve (SSSV) is required in every tubing string on all offshore wells. The wellhead includes all equipment on the surface that supports various pipe strings, seals off the well, and controls the paths and flow rates of reservoir fluids. The valves on the Christmas tree control the flow from the tubing. Three main ways to simulate permeability are explosive fracturing, acidizing, and hydraulic fracturing. Electric Submersible Pumps (ESPs) are used in high volume wells where volumes pumped are larger than can be handled by other artificial lift devices. Well testing can be done for the following reasons: To monitor the production capability of a well. To determine the changes in production capability of a well. To determine the reservoir drive mechanism. To estimate how much oil and gas might be recovered over time. The major methods of improved oil recovery are: water flooding, gas injection, chemical flooding, and thermal recovery. Heater-Treater: Emulsions are heated around F. The oil that separates from the emulsion floats to the top of the emulsion, the water that separates sinks to the bottom, and any gas evolving from the oil exits at the top. Natural gas is a mixture of methane, ethane, propane, and some heavier hydrocarbons such as butane, pentanes, nonanes and decanes. The development of lease automatic custody transfer (LACT) units has improved efficiency and reduced the time necessary to measure, sample, test, and transfer oil. Well service is maintenance work that usually involves repairs to equipment installed during completion of the well. Well workover includes procedures viewed as more complicated and expensive conducted on a well to restore or increase production.
Home Work 1. What are the four strings of pipe required for oil and gas wells? 2. What is the function of the Christmas tree? 3. What re three main ways to simulate permeability of reservoirs? 4. What are the reasons to do well testing? 5. What are the major methods of improved oil recovery? 6. What is natural gas a mixture of? 7. What is the difference between a well service and a well workover?